Hydrocarbon recovery operators have long recognized that defective oilfield tubulars which fail in a well may cause significant damage. A defective tubular which fails prior to hydrocarbon recovery may need to be repaired downhole. The repair costs, while significant, may be nominal compared to the loss of revenue from the delays in starting production. On occasion, a defective tubular may sever during run-in, thereby damaging downhole tools and resulting in an expensive fishing operation. A tubular which leaks during production may not be easily detected, and the lost production and premature shutting in of the well may be very costly.
Accordingly, oilfield tubulars are commonly inspected to ensure that defects in tubulars do not exceed established limits, thereby significantly reducing or eliminating the likelihood of downhole failures in the tubulars. Oilfield tubulars are most commonly inspected at either a pipe storage yard or at the production steel mill, although tubulars may also be inspected at the rig site, if necessary. Automated inspection equipment typically includes ultrasonic inspection stations and/or magnetic inspection stations. Also, the I.D. and/or the O.D. of each tubular may be checked for flaws. Inspection data from each tubular joint is stored in a computer. At periodic intervals during the inspection operation, the inspection operation is halted and flag reports are output for the prove-up operations.
As a result of the automated inspection, "passed" tubulars are either stored in a passed storage area or are promptly shipped to the rig site for use in a well, while "flagged" tubulars are placed in a proving area, where a proving operator manually inspects the suspect tubulars with portable equipment and gauges. The limits set by the initial inspection equipment must be sufficiently narrow to ensure that no tubulars with defects outside established limits are passed. In many cases, however, flagged tubulars may be manually inspected and still passed, although care obviously must be taken to carefully inspect each suspect defect in a flagged tubular. Depending on the results of the proving operation, a flagged tubular is either passed, rejected for use as a prime oilfield tubular, or sent to a repair area for repair (e.g., grinding the area containing the defect) or removal of the defect (e.g., cutting off an end of the tubular to remove the defect then rethreading the cut off end). In the alternative, some defects may be repaired by the prover in the prove-up area.
In many cases, the prover begins manual inspection of a flagged or suspect tubular only knowing that a tubular has been flagged, and that suspect defects are at identified locations along the tubular. A great deal of time is thus normally necessary to locate and check every suspect defect in a flagged tubular. A tubular joint occasionally may have so many suspect defects, or one or more suspect defects cannot be located, so that the prover walks from the proving area to the inspection area and requests a graphic output from the automated inspection equipment for a particular tubular joint. Since the automated inspection operation must be terminated to provide that output, and since there are significant demands for high production from the cost-intensive inspection equipment, the inspection equipment operator frequently will not want to shutdown the inspection equipment to provide the output desired by the prover for a particular tubular joint.
Flagged tubulars are marked by the prover so that the joints are either passed, rejected, or sent to the repair area. The prover conventionally fills out a defect summary sheet listing the results of the inspection of each suspect defect in a flagged tubular joint. Defect summary sheets are turned over to a supervisor for generating interim and/or final prove-up reports. Prove-up reports are maintained by the inspection service company as a record of passed tubulars that were initially flagged by the inspection equipment in order to ensure high quality control standards. The results of the initial inspection, the final prove-up report, and the records relating to tubulars which were repaired or cut off are then used by the tubular inspection company to generate a final inspection report and invoice for the customer. The customer utilizes the generated prove-up reports to analyze the overall inspection operation, to determine if additional tubulars must be shipped to the inspection yard in order to have sufficient accepted tubulars for a particular job, to support payment to the inspection service company for the inspection, proving, and tubular repair services, and to file a claim with the tubular manufacturer for rejected tubulars.
Various problems have long existed in performing these inspection operations, and particularly in performing prove-up operations in a reliable and cost effective manner. Prove-up reports are expensive and time consuming to generate, and transcription errors can be made between the prove-up data sheets and the prove-up reports. The usefulness of prove-up reports to the customer is also limited due to delays between completion of the prove-up operation on a tubular and the availability of a prove-up report for that tubular to the customer.
The disadvantages of the prior art are overcome by the present invention, and improved techniques and equipment are hereinafter disclosed for enhancing both the reliability and cost effectiveness of the operations involving the inspection of oilfield tubulars.